1. Field of the Invention
The present invention relates to a flow meter system and method, and more particularly, to a flow meter system and method for measuring flow characteristics of a three phase flow.
2. Statement of the Problem
Flow meters are used to measure the mass flow rate, density, and other characteristics of flowing materials. The flowing materials can comprise liquids, gases, combined liquids and gases, solids suspended in liquids, liquids including gases and suspended solids, etc.
Vibrating conduit sensors, such as Coriolis mass flow meters and vibrating densitometers, typically operate by detecting motion of a vibrating conduit that contains a flowing material. Properties associated with the material in the conduit, such as mass flow, density and the like, can be determined by processing measurement signals received from motion transducers associated with the conduit. The vibration modes of the vibrating material-filled system generally are affected by the combined mass, stiffness and damping characteristics of the containing conduit and the material contained therein.
A typical Coriolis mass flow meter includes one or more conduits that are connected inline in a pipeline or other transport system and convey material, e.g., fluids, slurries and the like, in the system. Each conduit may be viewed as having a set of natural vibration modes, including for example, simple bending, torsional, radial, and coupled modes. In a typical Coriolis mass flow measurement application, a conduit is excited in one or more vibration modes as a material flows through the conduit, and motion of the conduit is measured at points spaced along the conduit. Excitation is typically provided by an actuator, e.g., an electromechanical device, such as a voice coil-type driver, that perturbs the conduit in a periodic fashion. Mass flow rate may be determined by measuring time delay or phase differences between motions at the transducer locations. Density of the flow material can be determined from a frequency of a vibrational response of the flow meter. Two such transducers (or pickoff sensors) are typically employed in order to measure a vibrational response of the flow conduit or conduits and are typically located at positions upstream and downstream of the actuator. The two pickoff sensors are connected to electronic instrumentation by cabling, such as by two independent pairs of wires. The instrumentation receives signals from the two pickoff sensors and processes the signals in order to derive flow measurements.
Using recent advances in signal processing and meter design and taking note of fluid dynamics including mixing, bubble size, etc., a low frequency vibratory flow meter can be used to accurately measure the mixture density and mixture mass flow of a multiphase fluid stream. Although this is a big advancement, many flow meter users want to know the liquid-only density. The main application for a liquid-only density is in upstream oil and gas metering, for both three phase oilfield flow measurement and for liquid-only cement process measurement. A vibratory flow meter capable of measuring a liquid-only density would eliminate the need for a gas volume fraction meter to measure the gas volume fraction of a multi-phase flow. This would eliminate additional cost and complexity.
In the upstream oil and gas industry, oil wells typically produce water, oil, and natural gas. A separator is used to separate these components into a gas leg and a liquid leg. The density of the liquid leg is then measured and used to compute the fraction of oil and the fraction of water that make up the liquid stream. This measurement is simply a concentration measurement based on the measured density and is termed net oil computing. For example, if oil has a density of 0.8 g/cc and water has a density of 1.0 g/cc, a measured mixture density of 0.9 implies 50% water and 50% oil by volume. Similarly, a measured density of 0.95 implies 75% water and 25% oil by volume.
Where only two liquid phases are present and where the base densities of oil and water are known, the two phase component determination is relatively easy, with two equations and two unknowns. The basic equations comprise:Φoil+Φwater=1ρoilΦoil+ρwaterΦwater=ρmix 
Where the (Φ) term comprises a volumetric phase fraction and the (ρ) term comprises density. This can be written in matrix form as:
            [                                    1                                1                                                              ρ              oil                                                          ρ              water                                          ]        ⁢          {                                                  Φ              oil                                                                          Φ              water                                          }        =      {                            1                                                  ρ            mix                                }  
Inputting the water and oil density and measuring the mixture density with a vibratory flow meter, the standard net oil computing process calculates the volumetric phase fractions with a matrix inverse, comprising:
      {                                        Φ            oil                                                            Φ            water                                }    =                    [                                            1                                      1                                                                          ρ                oil                                                                    ρ                water                                                    ]                    -        1              ⁢          {                                    1                                                              ρ              mix                                          }      
Once the two phase fractions are known, they can be multiplied by a volume flow rate to determine the volume of water and the volume of oil that are being produced. In addition, the component mass flow rate can be calculated by multiplying the component volume flow rate by the component density.
In some cases, the liquid stream will still carry some gas, despite a separation process. This will occur when a pressure drop is present across a valve or flow measurement device. As a result, some entrained gas breaks out of the oil mixture. Gas break out will also occur when the separator is not working perfectly due to increased oil viscosity, stimulated production, or slugging through the well. In these cases, the gas present in the liquid stream results in very large errors in the actual water and oil production. For example, if a well is producing only water and natural gas and the output of the liquid leg of the separator includes 95% water and 5% gas, the indicated mixture density is 0.95 g/cc (assuming the gas density is zero) and the net oil computation assumes that the liquid stream is again 75% water and 25% oil. In reality, this well is producing no oil and the error in oil production is infinite.
A typical solution is the addition of a gas void fraction (GVF) meter. The gas fraction can be quantified by the GVF meter and the gas portion of the liquid density measurement can be removed. This eliminates large entrained gas errors in the net oil computing calculation.
When three phases are present there are three unknowns (phase fraction of oil, water, and natural gas) and another equation is required to solve the problem. As described above, in the past this third equation has come from a water-cut probe or gas void fraction meter. However, it is desired to make this measurement with a single Coriolis meter.
There remains a need in the art for a vibratory flow meter and method that can measure flow characteristics of a three phase flow.